Dielectric Logs
Operating/Interpretation Principles
Introduction
The dielectric constant of a material affects the way in which an electromagnetic wave passes through it. Since the dielectric constants of oil and water are different, the behavior of electromagnetic waves in reservoir rocks is of interest to well loggers. Two classes of tools are available for measuring the formation dielectric constant: low-frequency tools use coils on a mandrel and operate at tens of megahertz; high-frequency tools use microwave antennae on a pad contact device. These two types will be considered separately.
EPT
The high-frequency tool is known as the electromagnetic propagation tool (EPT). Its basic measurements are of propagation time and the attenuation of a 1.1 GHz electromagnetic wave as it passes through a specific interval of formation. As the propagation time in water is substantially higher than that in hydrocarbons, the EPT measurement is affected primarily by the water-filled porosity. Since, moreover, the propagation time in water is practically constant for most salinities, saturation estimations can be made without prior knowledge of the resistivity of the formation water. When other openhole log data are available, it is possible to distinguish between oil, gas, and water in reservoirs with unknown or changing Rw.
Physical Principle
There has long been a need for a method to determine water saturation that is less dependent on knowledge of water salinity. One such method is the measurement of dielectric permittivity. Except for water, most materials in sedimentary rocks have low values (less than 8); therefore, the measured dielectric permittivity is primarily a function of the water-filled porosity. Although the dielectric permittivity of water is influenced by salinity and temperature, its range is relatively modest and very much smaller than its range of resistivity.
Measurement Principle
The electromagnetic propagation tool is a pad-type tool ( Figure 1 ) with an antenna pad attached to the body of the tool. A backup arm has the dual purpose of pressing the pad against the borehole wall and providing a caliper measurement. A standard microlog pad is also attached to the main arm allowing a resistivity measurement to be made with a similar vertical resolution to the electromagnetic measurement. A smaller arm, exerting less force, is mounted on the same side of the tool as the pad and is used to detect rugosity of the borehole. The borehole diameter is the sum of the measurements from these two independent arms.
Two microwave transmitters and two receivers are mounted in the antenna pad assembly in a borehole-compensation array that minimizes the effects of borehole rugosity and tool tilt ( Figure 2 ).
The transmitter-receiver spacings of 8 cm and 12 cm are chosen to provide an optimum between several competing criteria: depth of investigation, determination of signal attenuation between receivers, and determination of phase difference in receiver signals ( Figure 3 ).
A 1.1 GHz electromagnetic wave is sent sequentially from each of the two transmitters, and at each of the receivers the amplitude and phase shift of the wave are measured ( Figure 4 ).
The absolute values of the amplitude and phase shift are found by comparison with an accurately known reference signal generated in the tool. The phase shift, the propagation time for the wave, tpl, and the attenuation A, over the receiver-receiver spacing, are calculated from the individual measurements. In each case, an average is taken of the measurements derived from the two transmitters. A complete borehole-compensated measurement is made sixty times per second; measurements are accumulated and averaged over an interval of either 2 or 6 in. of formation prior to recording on film and tape.
Due to the close proximity of the receivers to the transmitters, spherical waves are measured; therefore, a correction factor is applied to the measured attenuation so that the plane wave th cry may be used. The increased attenuation due to the spherical spreading of the wave is compensated for by applying a spherical loss correction factor SL. The corrected attenuation, Ac, is given by Ac = A - SL. In air, SL has a value of about 50 db, but, because the term is porosity dependent, a more exact approach can be taken when correcting downhole measurements:
SL = 45.0 + 1.3 tpl + 0.18tpl2
The formation dielectric parameters can then be obtained from the log data, since the attenuation factor, a, is directly proportional to the recorded attenuation, A, and the phase shift, b, is proportional to the propagation time
Tpl (= tpl).
The basic data available from the EPT sensors are Tpl and A. A separate tool section provides microlog and caliper measurements. A standard log presentation is shown in Figure 5 over an interval containing two sandstones (168-179 m and 202-207 m) separated by shale. Track 1 contains the borehole diameter (HD) and the micronormal (MNOR). The microinverse (MINV) resistivity curves, electromagnetic wave attenuation (EATT), and propagation time (TPL) are recorded in Tracks II and III. The measurement of the smaller caliper arm (SA) can be displayed to monitor the borehole rugosity, and hence the quality of the EPT data.
Interpretation Methods
The EPT measurement responds more to the water of a formation than to the matrix or any other fluid. The water present in a formation can be the original connate water, mud filtrate, or bound water associated with shales. Because of the shallow depth of investigation of the tool (1 to 6 in.), it can usually be assumed that only the flushed zone is influencing the measurement, hence the free water is filtrate.
Under normal circumstances, if fresh muds are used, the propagation time of the electromagnetic waves is essentially unaffected by the water salinity ( Figure 6 ). An increase in salinity increases the loss factor " and decreases the permittivity", but the effects tend to cancel each other out. If salt-saturated fluids are encountered, the loss factor increases to the extent that the electromagnetic waves are highly attenuated, and therefore measurements are more prone to error.
The EPT measurements are unaffected by mudcake up to a thickness of about 0.4 in., but rugosity can result in spurious readings as mud comes between the antenna pad and the formation. The situation deteriorates further in boreholes filled with air or oil, where even a thin film of the fluid results in the tool responding only to the fluid and not to the formation. The tool works well, however, in emulsion and inverse emulsion muds.
Porosity from Travel Time (tpo Method)
The most-used relationship to convert travel time to porosity is a weight-average relationship similar to that used in density logging.
Travel time of microwaves in clean, porous media is given by the sum of the travel times through the component parts:
tpo2 = tpl2 - Ac2/3604
tpo = tpf + (1 - ) tpm
Solving for the porosity,
= (tpo - tpm) / (tpf - tpm)
where:
Ac = the attenuation corrected for spreading loss
tpo = the loss-free travel time of the medium, ns/m
tpl
= the measured travel time of the medium, ns/m
tpm = the travel time of the rock matrix, ns/m
tpf
= the travel time of the fluid in the pores, ns/m
The tpl is measured by the tool, then the following may be calculated:
tpo2 = tpl2 - Ac2/3604
Once tpo is determined, the rest of the equations can be computed to obtain porosity ().
At the wellsite, a computation program computes the water volume from the EPT measurement using the tpo method and gives the amount of moved hydrocarbon.
Another method compares the EPT porosity with the total porosity measured by the neutron, density, and acoustic tools. This allows a quick-look determination of the water saturation in the flushed zone. Figure 7 is an example comparing the sonic porosity with the EPT porosity.
The sonic porosity (SPHI) and EPT porosity (EMCP) are displayed in Tracks II and III, and the computed gamma ray (CGR) and total gamma ray (SGR) are recorded in Track I. There is a change of lithology at 245 m, with a limestone above this depth and a sandstone with calcareous cement below. The limestone and lower section of the sandstone are water bearing, and the hydrocarbon content of the upper section of the sand is clearly indicated by the separation of the two porosity curves. The original oil/water contact is at 267 m, while the present contact is at 261 m. Generally, the EPT porosity reads the same as a nuclear-derived porosity in water-bearing zones and shales, but in hydrocarbon-bearing intervals the EPT porosity is less than either the total porosity or the density porosity. In gas zones, the separation between the neutron porosity and the EPT porosity is not so apparent.
Dielectric Constant Log (DCL)
In contrast to the EPT, other dielectric logging devices ( Figure 8 ) use a lower operating frequency (approximately 10 to 50 MHz) and a much longer spacing between transmitter and receiver (on the order of 3 ft). Since the tool measures formation properties beyond the invaded zone, it can be used for monitoring enhanced recovery projects where plastic pipe has been set. Figure 9 shows the progress of a waterflood through repeat logs on different dates.
Propagation of Electromagnetic Waves in Rocks
The dielectric constant of a material affects the way in which an electromagnetic wave passes through it. Since the dielectric constants of oil and water are different, the behavior of electromagnetic waves in reservoir rocks is of interest. Based on dielectric measurements, two classes of tools currently exist: very high and not-so-high frequency tools. Several such tools are
- electromagnetic propagation tool (EPT) (Schlumberger)
dielectric constant log (DCL) (Gearhart)
deep propagation tool (DPT) (Schlumberger)
The first of these is a very high frequency tool, the other two not so high. They all use small antenna arrays to send electromagnetic waves through the formation.
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